Top-down oil recovery

ABSTRACT

Methods relate to producing hydrocarbons, such as bitumen in an oil sands reservoir. The methods include utilizing an injector well with multiple horizontal laterals to provide downward fluid drive toward a producer well. Combined influence of gravity and a dispersed area of the fluid drive due to the laterals facilitate a desired full sweep of the reservoir. Fluids utilized for injection include water heated to less than 60 weight percent steam, solvent for the hydrocarbons and emulsifying agent for the hydrocarbons. The methods employing these fluids provide energy efficient recovery of the hydrocarbons.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application is a non-provisional application which claims benefitunder 35 USC §119(e) to U.S. Provisional Application Ser. No. 61/821,489filed May 9, 2013, entitled “TOP-DOWN OIL RECOVERY,” which isincorporated herein in its entirety.

STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH

None.

FIELD OF THE INVENTION

Embodiments of the invention relate generally to methods for recoveringoil utilizing wellbore configurations and an injection fluid fordownward drive of the oil toward a production well.

BACKGROUND OF THE INVENTION

Several techniques utilized to recover hydrocarbons in the form ofbitumen from oil sands rely on generated steam to heat and lowerviscosity of the hydrocarbons when the steam is injected into the oilsands. One common approach for this type of recovery includes steamassisted gravity drainage (SAGD). The hydrocarbons once heated becomemobile enough for production along with the condensed steam, which isthen recovered and recycled.

However, excessive heat loss to surrounding formations renders suchthermal processes ineffective and uneconomical in thin zones. Addingsolvent to the steam in the SAGD process provides some benefit to lowera steam to oil ratio. Rate of energy use requirements and heat loss tothe surrounding formations still makes recovery in thin zoneschallenging.

Alternative approaches inject various fluids, such as hot solvents, todrive the hydrocarbons toward a production well. These prior fluid drivetechniques often require volumes of expensive solvents higher than canbe justified. Further problems include premature breakthrough of thefluid at the production well due to channeling through a limited area ofthe formation rather than a desired full sweep across the formation.

Therefore, a need exists for methods of recovering hydrocarbons withlimited and efficient energy use per quantity of hydrocarbon production.

BRIEF SUMMARY OF THE DISCLOSURE

In one embodiment, a method of producing hydrocarbons includes forming amultilateral horizontal injector well in a hydrocarbon-bearing formationwith a horizontal length closer to an overburden upper boundary of thehydrocarbon-bearing formation than a lower boundary of thehydrocarbon-bearing formation and forming a horizontal producer well inthe hydrocarbon-bearing formation below at least part of the injectorwell. Heating the hydrocarbon-bearing formation without fluid transferbetween the injector and producer wells establishes fluid communicationbetween the injector and producer wells. Next, water heated to less than60 weight percent steam, solvent for the hydrocarbons and emulsifyingagent for the hydrocarbons passes through the injector well and into thehydrocarbon-bearing formation. Producing the hydrocarbons recovered atthe producer well by displacement results from combined forces ofgravity and a pressure differential maintained between the injector andproducer wells that provides a dispersed fluid drive due to the injectorwell being multilateral.

For one embodiment, a method of producing hydrocarbons includes forminga multilateral horizontal injector well in a hydrocarbon-bearingformation with a horizontal length within three meters of an upperboundary of the hydrocarbon-bearing formation and forming a horizontalproducer well in the hydrocarbon-bearing formation and extending in ahorizontal direction within ten meters of the injector well and threemeters of a lower boundary of the hydrocarbon-bearing formation. Waterheated to less than 60 weight percent steam, solvent for thehydrocarbons and emulsifying agent for the hydrocarbons passes throughthe injector well and into the hydrocarbon-bearing formation. Producingthe hydrocarbons recovered at the producer well by displacement resultsfrom combined forces of gravity and a pressure differential maintainedbetween the injector and producer wells that provides a dispersed fluiddrive due to the injector well being multilateral.

BRIEF DESCRIPTION OF THE DRAWINGS

A more complete understanding of the present invention and benefitsthereof may be acquired by referring to the following description takenin conjunction with the accompanying drawings in which:

FIG. 1 is a schematic of a pay zone with an upper horizontal injectionwell having laterals and a lower horizontal production well, accordingto one embodiment of the invention.

FIG. 2 is a schematic view of the injection well taken across line 2-2in FIG. 1, according to one embodiment of the invention.

FIG. 3 is a graph of cumulative energy injected versus cumulative oilproduced via a simulated recovery process utilizing an arrangement asshown in FIG. 1 and an injection fluid of wet steam, solvent and anemulsifying agent, according to one embodiment of the invention.

FIG. 4 is a graph of time versus energy intensity calculated for thesimulated recovery process, according to one embodiment of theinvention.

DETAILED DESCRIPTION

Turning now to the detailed description of the preferred arrangement orarrangements of the present invention, it should be understood that theinventive features and concepts may be manifested in other arrangementsand that the scope of the invention is not limited to the embodimentsdescribed or illustrated. The scope of the invention is intended only tobe limited by the scope of the claims that follow.

Embodiments of the invention relate to methods of producinghydrocarbons, such as bitumen in an oil sands reservoir. The methodsinclude utilizing an injector well with multiple horizontal laterals toprovide downward fluid drive toward a producer well. Combined influenceof gravity and a dispersed area of the fluid drive due to the lateralsfacilitate a desired full sweep of the reservoir. Fluids utilized forinjection include water heated to less than 60 weight percent steam,solvent for the hydrocarbons and emulsifying agent for the hydrocarbons.The methods employing these fluids provide energy efficient recovery ofthe hydrocarbons.

As used herein, the solvent refers to a fluid that can dilute heavy oiland/or bitumen. Examples of suitable candidates for non-aqueous fluidsthat may satisfy the selection criteria include C1 to C30 hydrocarbons,and combinations thereof. Some embodiments utilize condensing solventsor solvents that are liquid under reservoir conditions including C4 toC30 hydrocarbons, or combinations thereof. Examples of suitable solventsinclude, without limitation, gases, such as CO or CO₂ alone or withinmixtures like flue gas, alkanes such as methane, ethane, propane,butane, pentane, hexane, heptane, octane, nonane, decane, aromatics suchas toluene and xylene, as well as various available hydrocarbonfractions, such as condensate, gasoline, naphtha, diluent andcombinations thereof.

The emulsifying agent referenced herein includes any compound capable offorming an emulsion or other reduced viscosity mixture with thehydrocarbons relative to the hydrocarbons alone and that is stable underreservoir conditions, including thermally and chemically stablesurfactants, non-ionic, anionic, cationic, amphoteric or zwitterionicsurfactants, alkine metal carbonate or an alkaline metal hydroxide,aromatic sulfonates, alkyl benzyl sulfonates, olefin sulfonates, alkylaryl sulfonates, alkoxy sulfates, alkaline metal carbonates, alkalinemetal bicarbonates, alkaline metal hydroxides, sodium carbonate, sodiumbicarbonate, sodium hydroxide, potassium carbonate, potassiumbicarbonate, potassium hydroxide, magnesium carbonate and calciumcarbonate. Oil soluble surfactants which could be used include sorbitanfatty acid esters, saponified hard oils, saponified hydrogenated fattyacid oils, long chain fatty amines, long chain sulfates, long chainsulfonates, phospholipids, lignins, poly ethylene glycol mono-oleates,alkanolamide based surfactants, any other oil soluble surfactants andany combinations thereof.

Embodiments described herein utilize the water heated in a furnace, heatexchanger or other steam generators including direct steam generators toincrease temperature of the water for injection at between 50° and 250°C. or between 75° and 150° C. While the water may be heated up to, orbelow, a boiling point for the water at a pressure desired for injectionwithout generating any steam, some embodiments inject low quality or wetsteam when introduced into the well for injection into the reservoir.Such wet steam may contain less than 60 weight percent steam or lessthan 50 weight percent steam, with a remainder of the water being inliquid phase.

For comparison, conventional steam assisted gravity drainage relies onhigher quality steam (e.g., at least 95 weight percent steam) to formand rise into a steam chamber before condensing upon contact with thehydrocarbons in the reservoir. The water heated to less than 60 weightpercent steam limits amount of energy needed since less than half theenergy is needed relative to making pure steam and also limits energyloss. Such energy loss can result from the steam transferring heat to anoverburden rather than the hydrocarbons in the reservoir.

FIG. 1 depicts a hydrocarbon-bearing formation 100 bounded by anoverburden upper layer 102 and a lower layer 104. The upper and lowerlayers 102, 104 may include shale or other less permeable geologicstrata than the formation 100, which forms a reservoir pay zone. Whilenot limited to any particular thickness of the formation 100,embodiments of the invention may provide economic recovery even withdistances separating the upper and lower layers 102, 104 of less than 20meters, less than 15 meters or less than 10 meters.

An upper horizontal injector well 108 having laterals 110 extendsthrough the formation 100 above a lower horizontal producer well 106.Location of the injector well 108 in the formation 100 disposes ahorizontal length of the injector well 108 with the laterals 110 closerto the upper layer 102 than the lower layer 104. In some embodiments,the injector well 108 only extends into a top quarter of the formation100 with the producer well 106 extending to have a horizontal bore in abottom quarter of the formation 100. For example, forming the injectorwell 108 may place a horizontal length of the injector well 108 withinthree meters of the upper layer 102 (e.g., one meter from the upperlayer 102) and ten meters of the producer well 106 extending in ahorizontal direction within three meters of the lower layer 104.

For some embodiments, the horizontal bore of the producer well 106aligns in a vertical direction below a main bore of the injector well108 from which the laterals 110 branch outward. The producer well 106may also include horizontal multilaterals like the injector well 108.Any portion of the injector well 108 may cover part of the producer well106 regardless of orientation, location or configuration of the producerwell 106 relative to the injector well 108 in order to achieve desiredfluid drive infrastructure.

FIG. 2 shows a top view of the injector well 108 taken across line 2-2in FIG. 1. In some embodiments, the injector well 108 may include atleast two of the laterals 110 on each side of the main bore along thehorizontal length of the injector well 108 and in a common plane withthe main bore. The plane formed by all eight of the laterals 110depicted in FIG. 2 thus runs substantially parallel in proximity withthe upper layer 102.

In operation, a preheating stage establishes fluid communication betweenthe injector and producer wells 108, 106. Initial viscosity of thehydrocarbons in the formation 100 prevents such fluid transfer betweenthe injector and producer wells 106, 108 until after the preheatingstage. The preheating stage may take at least one week, at least onemonth, or at least six months to establish this fluid communicationdepending upon properties of the formation 100 and techniques utilizedto introduce the heat. These techniques for the preheating stage includeat least one of electric resistive heating, radio frequency heating,electromagnetic heating and steam circulation with steam injection andproduction occurring in a same one of the injector and producer wells108, 106 even though one or both may be used for such steam circulation.

After the preheating stage, the water that is heated, the solvent andthe emulsifying agent flow through the injector well 108 and pass fromthe laterals 110 into the formation 100. In some embodiments, thesefluids form a mixture for injection together whether continuous orintermittent. Exemplary suitable alternative injection strategies mayinclude injecting either or both the solvent and the emulsifying agentintermittently or sequentially, such as when the water that is heated isinjected at intermittent intervals between when the solvent and theemulsifying agent are injected.

Volume fractions of the water, the solvent and the emulsifying agent mayvary for particular properties of the formation 100. In someembodiments, the water makes up at least 90 volume percent or at least95 volume percent of a combined quantity of the water and solventinjected. Adjusting total fluid injection rate of the water, the solventand the emulsifying agent maintains a constant injection bottom-holepressure in some embodiments.

The emulsifying agent creates an oil-in-water emulsion with relativelower viscosity than the hydrocarbons alone. The solvent also lowers theviscosity of the hydrocarbons by dilution into the hydrocarbons. Heattransfer from the water to the hydrocarbons further works in synergywith the solvent in reducing the viscosity of the hydrocarbons.

In some embodiments, a pressure differential of at least 15-20kilopascals per meter of well separation maintained between the injectorwell 108 and the producer well 106 facilitates fluid drive of thehydrocarbons in the formation 100. A combined influence of gravity andthe fluid drive with the laterals 110 used for the injection creates apiston-like force directing the hydrocarbons towards the producer well106 to facilitate a uniform and complete sweep of the formation 100while limiting injected fluid flow channeling. For example, gravityprovides a driving force of 9.8 kilopascals per meter that combines with15-20 kilopascals per meter when a differential pressure of 90-120kilopascals is maintained between the injector well 108 and the producerwell 106 if separated by 6 meters.

The following examples of certain embodiments of the invention aregiven. Each example is provided by way of explanation of the invention,one of many embodiments of the invention, and the following examplesshould not be read to limit, or define, the scope of the invention.

An evaluation of the processes described herein was carried out using anumerical simulator (STARS by CMG) and based on a configuration as shownin FIGS. 1 and 2. Hexane and sodium hydroxide provided the solvent andthe emulsifying agent, respectively. The evaluation utilized anAthabasca oil sands reservoir of 120 meters in width by 8 meters inheight and 500 meters in length.

With reference to FIGS. 1 and 2, the producer well 106 extended in ahorizontal direction 500 meters in length 1 meter above the lower layer104. The injector well 108 included a total of eight of the laterals 110with four each per side of the main bore and each extending 60 meters inlength while being separated from one another by 100 meters along themain bore. A distance of 6 meters in a vertical direction separated themain bore of the injector well 108 from the horizontal bore of theproducer well 106.

The preheating stage lasted for six months to establish the fluidcommunication before initiating top-down displacement, as describedherein. During injection after the preheating stage, the water made up95 volume percent of a combined quantity of the water and solventinjected as a mixture with the emulsifying agent. Total fluid injectionrate adjustments maintained the bottom-hole pressure at 3.4 megapascals.A pressure differential between the injector and producer wells of 140kilopascals, above the hydrostatic head between the wells, contributedto the driving force with gravity.

A steam-only case used all like parameters except that only steam, inwhich quality was 95 weight percent steam, was used for injectionwithout the solvent and the emulsifying agent. Energy content of thesteam in this steam-only case was about twice as much relative to themixture. Although the steam-only case does not compare prior art methodsto embodiments of the invention, the steam-only case in comparison withuse of the mixture provides a baseline for putting energy efficiencyinto context. The comparison also shows unexpected results in that themixture still enabled desired cumulative production quantities even withsuch limited energy input and also in that these improvements indicatethat using water or wet steam with less energy provides superior resultsthan co-injecting additives, such as the solvent, with relative higherenergy steam where only 30-35% improvements in steam-to-oil ratios areexpected.

FIG. 3 illustrates a graph of cumulative energy injected versuscumulative oil produced as determined in the evaluation. The graph showsincrease in oil production from the same amount of energy injected usingthe mixture (represented by curve 300) as compared to the steam-onlycase (represented by curve 302). After injection of about 1.5 millionGiga Joules of energy, an increase in oil production of about 56% wasobtained with the mixture 300 relative to the steam-only case 302. Toproduce an equal 50,000 cubic meters of oil using either the mixture 300or the steam-only case 302, the amount of energy required with themixture 300 was only 0.6 million Giga Joules, which amounts to more than50% savings in energy, compared to about 1.5 million Giga Joules for thesteam-only case 302.

FIG. 4 shows a graph of time versus energy intensity calculated for thesimulated recovery process. The graph shows that utilizing the mixture(represented by curve 400) lowers the energy intensity as compared tothe steam-only case (represented by curve 402). By the end of 7 years ofinjection, the energy intensity with use of the mixture 400 was 2.6 ascompared to 5.2 for the steam-only case 402, which difference representsa reduction of 50%.

In closing, it should be noted that the discussion of any reference isnot an admission that it is prior art to the present invention,especially any reference that may have a publication date after thepriority date of this application. At the same time, each and everyclaim below is hereby incorporated into this detailed description orspecification as additional embodiments of the present invention.

Although the systems and processes described herein have been describedin detail, it should be understood that various changes, substitutions,and alterations can be made without departing from the spirit and scopeof the invention as defined by the following claims. Those skilled inthe art may be able to study the preferred embodiments and identifyother ways to practice the invention that are not exactly as describedherein. It is the intent of the inventors that variations andequivalents of the invention are within the scope of the claims whilethe description, abstract and drawings are not to be used to limit thescope of the invention. The invention is specifically intended to be asbroad as the claims below and their equivalents.

1. A method of producing hydrocarbons, comprising: forming amultilateral horizontal injector well in a hydrocarbon-bearing formationwith a horizontal length closer to an overburden upper boundary of thehydrocarbon-bearing formation than a lower boundary of thehydrocarbon-bearing formation; forming a horizontal producer well in thehydrocarbon-bearing formation below at least part of the injector well;heating the hydrocarbon-bearing formation without fluid transfer betweenthe injector and producer wells to establish fluid communication betweenthe injector and producer wells; introducing water heated to less than60 weight percent steam, solvent for the hydrocarbons and emulsifyingagent for the hydrocarbons through the injector well and into thehydrocarbon-bearing formation; and producing the hydrocarbons recoveredat the producer well by displacement resulting from combined forces ofgravity and a pressure differential maintained between the injector andproducer wells that provides a dispersed fluid drive due to the injectorwell being multilateral.
 2. The method according to claim 1, wherein theinjector well includes at least four laterals in a common plane with thehorizontal length of the injector well.
 3. The method according to claim1, wherein the pressure differential is at least 15-20 kilopascals permeter of separation between the injector and producer wells.
 4. Themethod according to claim 1, wherein the solvent includes hydrocarbonswith between 1 and 30 carbon atoms per molecule.
 5. The method accordingto claim 1, wherein the emulsifying agent is a thermally and chemicallystable surfactant at reservoir conditions.
 6. The method according toclaim 1, wherein the emulsifying agent is selected from the groupconsisting of aromatic sulfonates, alkyl benzyl sulfonates, olefinsulfonates, alkyl aryl sulfonates, alkoxy sulfates, alkaline metalcarbonates, alkaline metal bicarbonates and alkaline metal hydroxides.7. The method according to claim 1, wherein the emulsifying agentincludes sodium hydroxide.
 8. The method according to claim 1, whereinthe solvent includes hydrocarbons with between 4 and 30 carbon atoms permolecule and the emulsifying agent is sodium hydroxide.
 9. The methodaccording to claim 1, wherein the injector well is disposed in a topquarter of the hydrocarbon-bearing formation and the producer well isdisposed in a bottom quarter of the hydrocarbon-bearing formation. 10.The method according to claim 1, wherein the heating to establish fluidcommunication between the injector and producer wells includes at leastone of electric resistive heating, radio frequency heating,electromagnetic heating and steam circulation with steam injection andproduction occurring in a same one of the injector and producer wells.11. The method according to claim 1, wherein the water makes up at least90 volume percent of a combined quantity of the water and solventinjected.
 12. The method according to claim 1, wherein the producer wellincludes horizontal multilaterals.
 13. The method according to claim 1,wherein the water, the solvent and the emulsifying agent are injectedtogether as a mixture.
 14. The method according to claim 1, wherein thewater is injected at intermittent intervals between when the solvent andthe emulsifying agent are injected.
 15. A method of producinghydrocarbons, comprising: forming a multilateral horizontal injectorwell in a hydrocarbon-bearing formation with a horizontal length withinthree meters of an upper boundary of the hydrocarbon-bearing formation;forming a horizontal producer well in the hydrocarbon-bearing formationand extending in a horizontal direction within ten meters of theinjector well and three meters of a lower boundary of thehydrocarbon-bearing formation; introducing water heated to less than 60weight percent steam, solvent for the hydrocarbons and emulsifying agentfor the hydrocarbons through the injector well and into thehydrocarbon-bearing formation; and producing the hydrocarbons recoveredat the producer well by displacement resulting from combined forces ofgravity and a pressure differential maintained between the injector andproducer wells that provides a dispersed fluid drive due to the injectorwell being multilateral.
 16. The method according to claim 15, whereinthe emulsifying agent is selected from the group consisting of aromaticsulfonates, alkyl benzyl sulfonates, olefin sulfonates, alkyl arylsulfonates, alkoxy sulfates, alkaline metal carbonates, alkaline metalbicarbonates and alkaline metal hydroxides.
 17. The method according toclaim 15, wherein the solvent is a hydrocarbon that is liquid underreservoir conditions.
 18. The method according to claim 15, wherein ahorizontal bore of the producer well aligns in a vertical directionbelow a main horizontal bore of the injector well.
 19. The methodaccording to claim 15, wherein the producer well includes horizontalmultilaterals.
 20. The method according to claim 15, wherein theinjector well includes at least two laterals on each side of a main borealong the horizontal length of the injector well and in a common planewith the main bore.